Substations in high and medium-voltage power networks include primary devices such as electrical cables, lines, bus bars, switches, power transformers and instrument transformers, which are generally arranged in switch yards and/or bays. These primary devices are operated in an automated way via a Substation Automation (SA) system. The SA system includes secondary devices, such as Intelligent Electronic Devices (IED) which are responsible for protection, control and monitoring of the primary devices. The secondary devices may be hierarchically assigned to a station level or a bay level of the SA system. The station level can include a supervisory computer, which has an Operator Work Station (OWS) with a Human-Machine Interface (HMI) and runs a station-level Supervisory Control And Data Acquisition (SCADA) software, as well as a gateway that communicates the state of the substation to a Network Control Centre (NCC) and receives commands from the NCC. IEDs on the bay level, which are also termed bay units, in turn are connected to each other as well as to the IEDs on the station level via an inter-bay or station bus primarily serving the purpose of exchanging commands and status information.
Secondary devices on a process-level of the SA system can include, for example, conventional Instrument Transformers (IT) for voltage (Voltage Transformers VT) and current (Current Transformers CT) measurement, gas density or pressure sensors, as well as contact probes for sensing switch and transformer tap changer positions. Furthermore, exemplary intelligent sensors such as non-conventional electronic or optical sensors for current or voltage can include an Analog to Digital (A/D) converter for sampling of analog signals, and can be connected to the bay units via a dedicated bus, or a dedicated communication service on a common communication system, as part of an intelligent process interface. The intelligent process interface replaces the conventional hard-wired process interface that connects conventional ITs in the switchyard, via dedicated copper wires and junction boards, to different bay units which individually sample the analog signals from the ITs.
A communication standard for communication between the secondary devices of a substation has been introduced by the International Electrotechnical Committee (IEC) as part of the standard IEC 61850 entitled “Communication Networks and Systems in Substations”. For non-time critical report messages, section IEC 61850-8-1 specifies the Manufacturing Message Specification (MMS, ISO/IEC 9506) protocol based on a reduced Open Systems Interconnection (OSI) protocol stack with the Transmission Control Protocol (TCP) and Internet Protocol (IP) in the transport and network layer, respectively, and Ethernet and/or RS-232C as physical media. For time-critical event-based messages, such as trip commands, for example, IEC 61850-8-1 specifies the Generic Object Oriented Substation Events (GOOSE) directly on the Ethernet link layer of the communication stack. For very fast periodically changing signals at the process level, such as measured analog voltages or currents, section IEC 61850-9-2 specifies the Sampled Value (SV) service, which, similar to GOOSE, builds directly on the Ethernet link layer. Hence, part 9 of the standard defines a format to publish, as multicast messages on an industrial Ethernet, digitized measurement data from current or voltage sensors on the process level as a substitute to traditional copper wiring.
SA systems based on IEC61850 are configured by means of a standardized configuration representation or formal system description called Substation Configuration Description (SCD). An SCD file comprises the logical data flow between the IEDs on a “per message” base, i.e. for every message source, a list of destination or receiver IEDs, the message size in terms of data set definitions, as well as the message sending rates for all periodic traffic such as reports, GOOSE, and SV.
As mentioned, IEC 61850 introduces different communication services for Substation Automation applications. A predictable and deterministic communication time is desired for at least the real time safety and protection related functions among these applications. However, the communication load can become an issue for large process control systems with up to 500 IEDs, for example, communicating among each other and with increased real-time critical communication needs due to multicast communication traversing the entire system. This is especially true for multicast GOOSE and SV messages according to IEC 61850, and has an impact on the entire communication system, e.g., the behaviour of a switch based Ethernet, as well as on individual message transmitters and receivers. While the performance of a communication stack of a transceiver can depend on computing (e.g., CPU processing) performance and quality of the implementing software, other causes such as application tasks sharing the CPU, or a connection to the application via queues or shared memory, might have an impact on the communication stack processing time as well.
If a mission-critical application is dependent on guaranteed real-time performance, the choice can be a deterministic protocol where the communication behavior can be calculated in advance. Examples are periodic busses as defined in, for example, IEC 61375 (Multi-function Vehicle Bus MVB) or the WorldFIP real time fieldbus. According to these, a maximum possible amount of data is transferred permanently, so that the fixed communication time is always according to the maximum load possible. However, the latter does not apply to the Ethernet based non-periodic bus adopted by IEC 61850. Here, switches are used to remove the effect of collisions, and effects of queuing in the switches could be expected in case of high communication load. On the other hand, in an Ethernet system with a capacity of 100 MB/s or even 1 GB/s, the bottle necks, for most current SA applications, reside in the end devices (IEDs) and not in the switch based Ethernet system.
In EP 1610495, fault analysis for analyzing a cause of a performance fault on a communication network is performed during execution of a communication application. For this purpose, messages or packets are captured, and ongoing message transfers as well as times of message appearance on the bus are logged, such as during high load situations or when forcing certain request/response schemes. Based on the logged times, round trip times and message throughput can be determined. However, this approach is only valid for the investigated scenarios, and only limited conclusions for other scenarios can be drawn from them. In addition, the quality-of-service analysis is restricted to the communication level, independent of the effect of an event at an application or function level.
The principles and methods of the present disclosure are by no means restricted to use in substation automation, but are likewise applicable to other Process Control systems with a standardized configuration description. For example, it has to be noted that IEC 61850 is also an accepted standard for Hydro power plants, Wind power systems, and Distributed Energy Resources (DER).